Method for refrigerating liquefied gas and installation therefor

ABSTRACT

The invention concerns a method for refrigerating liquefied natural gas under pressure ( 1 ), comprising a first step wherein the LNG ( 1 ) is cooled, expanded and separated (a) in a first base fraction ( 4 ) which is collected, and (b) a first top fraction ( 3 ) which is heated, compressed in a compressor (K 1 ) and cooled into a first compressed fraction ( 5 ) which is collected; a second compressed fraction ( 6 ) is drawn from the fuel gas ( 5 ), cooled then mixed with the cooled and expanded LNG ( 1 ). The invention is characterised in that it comprises a second step wherein the second compressed fraction ( 6 ) is compressed and cooled, and a flux is ( 8 ) drawn and cooled, expanded and introduced in the compressor (K 1 ). The invention also describes other embodiments.

The present invention relates, in general, and according to a first ofits aspects, to the gas industry and, in particular, to a method forrefrigerating pressurized gas containing methane and C2 and higherhydrocarbons, so as to separate them.

More specifically, the invention relates, according to its first aspect,to a method for refrigerating a pressurized liquefied natural gascontaining methane and C2 and higher hydrocarbons, comprising a firststep (I) in which step (Ia) said pressurized liquefied natural gas isexpanded to provide an expanded liquefied natural gas stream, in whichstep (Ib) said expanded liquefied natural gas is split into a relativelymore volatile first top fraction and a relatively less volatile firstbottom fraction, in which step (Ic) the first bottom fraction consistingof refrigerated liquefied natural gas is collected, in which step (Id)the first top fraction is heated, compressed in a first compressor andcooled to provide a first fuel gas compressed fraction which iscollected, in which step (Ie) there is tapped off from the firstcompressed fraction a second compressed fraction which is then cooled,then mixed with the expanded liquefied natural gas stream.

Refrigeration methods of this type are well known to those skilled inthe art and have been in use for many years.

The method for refrigerating liquefied natural gas (LNG) according tothe above preamble is used in the known way with a view to eliminatingthe nitrogen present sometimes in large quantities in the natural gas.In this case, the fuel gas obtained using this method is nitrogen-rich,whereas the refrigerated liquefied natural gas is nitrogen-depleted.

Installations for liquefying natural gas have well-defined technicalcharacteristics and limits dictated by the capacity of the productionelements of which they are made. In consequence, an installationproducing liquefied natural gas is limited by its maximum productioncapacity, under normal operating conditions. The only way to increaseproduction consists in building a new production unit.

Given the cost that such an investment represents, it is necessary tomake sure that the desired increase in production will be lasting, so asto make the cost easier to amortize.

At the present time there is no way to increase production of aliquefied natural gas production unit, even temporarily, when this unitis running at full capacity, without resorting to heavy and expensiveinvestment consisting in building another production unit.

The liquefied natural gas (LNG) production capacity depends essentiallyon the power of the compressors used to refrigerate and liquefy thenatural gas.

This being the case, a first object of the invention is to propose amethod, in other respects in accordance with the generic definitiongiven in the above preamble, that allows the capacity of an LNGproduction unit to be increased without having to resort to buildinganother LNG production unit, and which is essentially characterized inthat the method comprises a second step (II) in which step (IIa) thesecond compressed fraction is compressed in a second compressor coupledto an expansion turbine to provide a third compressed fraction, in whichstep (IIb) the third compressed fraction is cooled, then split into afourth compressed fraction and a fifth compressed fraction, in whichstep (IIc) the fourth compressed fraction is cooled and expanded in theexpansion turbine coupled to the second compressor to provide anexpanded fraction which is then heated, then introduced into amedium-pressure first stage of the compressor, and in which step (IId)the fifth compressed fraction is cooled, then mixed with the expandedliquefied natural gas stream.

A first merit of the invention is that it has discovered that aproduction unit running at 100% capacity, producing a certain deliveryof liquefied natural gas at a temperature of −160° C. and at a pressureclose to 50 bar, all other operating parameters being constant, can haveits delivery, and therefore its production, increased only by increasingthe temperature at which the liquefied natural gas is produced.

However, the LNG is stored at about −160° C. at low pressure (under 1.1bar absolute), and an increase in its storage temperature would lead toan increase in its storage pressure, and this represents prohibitivecosts, and above all difficulties with transport, because of the verylarge quantities of LNG produced.

In consequence, it is common practice for the LNG to be prepared at atemperature close to −160° C. prior to its being stored.

A second merit of the invention is that it presents an elegant solutionto these limits on production by using a method for refrigerating LNGthat can be adapted to an already-existing method for producing LNG, notrequiring the use of significant financial and concrete means toimplement this method. This solution comprises the production, by analready-existing LNG production unit, of LNG at a temperature aboveabout −160° C., then refrigerating it to about −160° C. using the methodaccording to the invention.

A third merit of the invention is that it has modified a known method inaccordance with the preamble above for refrigerating nitrogen-richliquefied natural gas and that it has allowed it to be used both withnitrogen-rich LNG and with nitrogen-depleted LNG. In the latterinstance, the fuel gas obtained using this method contains very littlenitrogen, and therefore has a composition close to that of thenitrogen-depleted liquefied natural gas.

According to a first aspect of the method of the invention, the expandedliquefied natural gas stream can be split, prior to step (Ib), into asecond top fraction and a second bottom fraction, the second topfraction can be heated, then introduced into the first compressor in anintermediate medium-pressure second stage between the medium-pressurefirst stage and a low-pressure stage, and the second bottom fraction canbe split into the first top fraction and the first bottom fraction.

According to the first aspect of the method of the invention, eachcompression step can be followed by a cooling step.

According to a second of its aspects, the invention relates to arefrigerated liquefied natural gas and a fuel gas obtained by any one ofthe above-defined methods.

According to a third of its aspects, the invention relates to aninstallation for refrigerating a pressurized liquefied natural gascontaining methane and C₂ and higher hydrocarbons, comprising means forcarrying out a first step (I) in which step (Ia) said pressurizedliquefied natural gas (1) is expanded to provide an expanded liquefiednatural gas stream, in which step (Ib) said expanded liquefied naturalgas is split into a relatively more volatile first top fraction and arelatively less volatile first bottom fraction, in which step (Ic) thefirst bottom fraction consisting of refrigerated liquefied natural gasis collected, in which step (Id) the first top fraction is heated,compressed in a first compressor and cooled to provide a first fuel gascompressed fraction which is collected, in which step (Ie) there istapped off from the first compressed fraction a second compressedfraction which is then cooled, then mixed with the expanded liquefiednatural gas stream, characterized in that the installation comprisesmeans for carrying out a second step (II) in which step (IIa) the secondcompressed fraction is compressed in a second compressor coupled to anexpansion turbine to provide a third compressed fraction, in which step(IIb) the third compressed fraction is cooled, then split into a fourthcompressed fraction and a fifth compressed fraction, in which step (IIc)the fourth compressed fraction is cooled and expanded in the expansionturbine coupled to the second compressor to provide an expanded fractionwhich is then heated, then introduced into a medium-pressure first stageof the compressor, and in which step (IId) the fifth compressed fractionis cooled, then mixed with the expanded liquefied natural gas stream.

According to a first alternative form according to its third aspect, theinvention relates to an installation comprising means for splitting theexpanded liquefied natural gas stream, prior to step (Ib), into a secondtop fraction and a second bottom fraction, in that the installationcomprises means for heating, then introducing the second top fractioninto the first compressor in an intermediate medium-pressure secondstage between the medium-pressure first stage and a low-pressure stage,and in that it comprises means for splitting the second bottom fractioninto the first top fraction and the first bottom fraction.

According to a first embodiment according to its third aspect, theinvention relates to an installation in which the first top fraction andthe first bottom fraction are separated in a first separating vessel.

According to a second embodiment according to its third aspect, theinvention relates to an installation in which the first top fraction andthe first bottom fraction are separated in a distillation column.

According to one embodiment according to the first alternative form ofits third aspect, the invention relates to an installation in which theexpanded liquefied natural gas stream can be split into the second topfraction and the second bottom fraction in a second separating vessel.

According to its second embodiment according to its third aspect, theinvention relates to an installation in which the distillation columncomprises at least one lateral and/or column-bottom reboiler, in thatliquid tapped off a plate of the distillation column passing throughsaid reboiler is heated in a second heat exchanger, then reintroducedinto the distillation column at a stage below said plate, and in thatthe expanded liquefied natural gas stream is cooled in said second heatexchanger.

According to a third embodiment according to its third aspect, theinvention relates to an installation in which the cooling of the firsttop fraction and of the expanded fraction, and the heating of the fourthcompressed fraction and of the fifth compressed fraction take place inone and the same first heat exchanger.

According to the first alternative form according to its third aspect,the invention relates to an installation in which the second topfraction is heated in the first heat exchanger.

The invention will be better understood and other objects, features,details and advantages thereof will become more clearly apparent in thecourse of the description which follows with reference to the attachedschematic drawings given solely by way of nonlimiting example and inwhich:

FIG. 1 depicts a functional block diagram of an installation forliquefying natural gas according to one embodiment of the prior art;

FIG. 2 depicts a functional block diagram of an installation forremoving nitrogen from liquefied natural gas according to a firstembodiment of the prior art;

FIG. 3 depicts a functional block diagram of an installation forremoving nitrogen from liquefied natural gas according to a secondembodiment of the prior art;

FIGS. 4, 5, 6 and 7 depict functional block diagrams of installationspossibly for removing nitrogen from liquefied natural gas according tosome preferred embodiments of the invention.

In these seven figures, there are the symbols “FC”, which stands for“flow controller”, “GT” which stands for “gas turbine”, “GE” whichstands for “electric generator”, “LC” which stands for “liquid levelcontroller”, “PC” which stands for “pressure controller”, “SC” whichstands for “speed controller” and “TC” which stands for “temperaturecontroller”.

For clarity and succinctness, the pipes used in the installations ofFIGS. 1 to 7 will be identified by the same reference symbols as thegaseous fractions passing through them.

Referring to FIG. 1, the installation depicted is intended, in a knownway, to treat a dried, desulfurized and decarbonated natural gas 100, toobtain liquefied natural gas 1, generally available at a temperaturebelow −120° C.

This installation for liquefying LNG has two independent coolingcircuits. A first cooling circuit 101, corresponding a propane cycle,makes it possible to obtain primary cooling to about −30° C. in anexchanger E3 by expanding and vaporizing liquid propane. The heated andexpanded propane vapor is then compressed in a second compressor K2,then the compressed gas 102 obtained is then cooled and liquefied inwater coolers 103, 104 and 105.

A second cooling circuit 106, corresponding in general to a cycleoperating on a mixture of nitrogen, methane, ethane and propane, allowssignificant cooling of the natural gas that is to be treated, to obtainliquefied natural gas 1. The heat transfer fluid present in the secondcooling cycle is compressed in a third compressor K3 and cooled in waterexchangers 118 and 119 and is then cooled in a water cooler 114 toobtain a fluid 107. The latter is then cooled and liquefied in theexchanger E3 to provide a cooled and liquefied stream 108. The latter isthen split into a vapor phase 109 and a liquid phase 110 which are bothintroduced into the lower part of a cryogenic exchanger 111. Aftercooling, the liquid phase 110 then leaves the exchanger 111 to beexpanded in a turbine X2 coupled to an electric generator. The expandedfluid 112 is then introduced into the cryogenic exchanger 111 above itslower part, where it is used to cool the fluids passing through thelower part of the exchanger, by being sprayed onto the pipes conveyingthe fluids that are to be cooled, using spray booms. The vapor phase 109passes through the lower part of the cryogenic exchanger 111 where it iscooled and liquefied, and is then cooled further by passing through anupper part of the cryogenic exchanger 111. Finally, this cooled andliquefied fraction 109 is expanded in a valve 115, then used to cool thefluids passing through the upper part of the cryogenic exchanger 111, byspraying it onto the pipes conveying the fluids that are to be cooled.The liquid coolants sprayed inside the cryogenic exchanger 111 are thencollected at the bottom of the exchanger to provide the stream 106 whichis sent to the compressor K3.

The dried, desulfurized and decarbonated natural gas 100 is cooled in apropane heat exchanger 113 and then subjected to a drying treatment,which may, for example, involve passing it over a molecular sieve, forexample made of zeolite, and to a demercurization treatment, for exampleby passing it over a silver foam or over any other mercury trap, in achamber 116 to provide a purified natural gas 117. The latter is thencooled and partially liquefied in the heat exchanger E3, passes throughthe lower part, then through the upper part of the cryogenic exchanger111 to provide a liquefied natural gas 1. The latter is customarilyobtained at a temperature below −120° C.

Referring now to FIG. 2, the installation depicted is intended, in theknown way, to treat a nitrogen-rich liquefied natural gas 1 to obtain,on the one hand, a nitrogen-depleted cooled liquefied natural gas 4 and,on the other hand, a first compressed fraction 5 which is anitrogen-rich compressed fuel gas.

The LNG 1 is first of all expanded and cooled in an expansion turbine X3which is regulated by a flow controller controlling the flow of LNGpassing through the pipe 1, then is expanded and cooled again in a valve18 the opening of which is dependent on the pressure of the LNG leavingthe compressor X3, to provide an expanded liquefied natural gas stream2. The latter is then split into a relatively more volatile first topfraction 3 and a relatively less volatile bottom fraction 4 in a vesselV1. The first bottom fraction 4 consisting of cooled liquefied naturalgas is collected and pumped in a pump P1, passes through a valve 19, theopening of which is regulated by a level controller controlling thelevel of liquid in the bottom of the vessel V1, to then leave theinstallation and go for storage.

The first top fraction 3 is heated in a first heat exchanger E1 and isthen introduced into a low-pressure stage 15 of a compressor K1 coupledto a gas turbine GT. This compressor K1 comprises a plurality ofcompression stages 15, 14, 11 and 30, at progressively higher pressures,and a plurality of water coolers 31, 32, 33 and 34. After eachcompression stage, the compressed gases are cooled by passing themthrough a heat exchanger, preferably a water heat exchanger. The firsttop fraction 3, at the end of the compression and cooling steps,provides the nitrogen-rich compressed fuel gas 5. This fuel gas is thencollected and leaves the installation.

A small part of the fuel gas 5 which corresponds to a stream 6 is tappedoff. This stream 6 is cooled in the exchanger E1, giving up its heat tothe first top fraction 3, to yield a cooled stream 22. This cooledstream 22 then flows through a valve 23 the opening of which iscontrolled by a flow controller at the outlet of the exchanger E2. Thestream 22 is finally mixed with the expanded liquefied natural gasstream 2.

Referring now to FIG. 3, the installation depicted is intended, in theknown way, to treat a nitrogen-rich liquefied natural gas 1 to obtain,on the one hand, a cooled and nitrogen-depleted liquefied natural gas 4and, on the other hand, a first compressed fraction 5 which is anitrogen-rich compressed fuel gas. In this installation, the separatingvessel V1 has been replaced by a distillation column C1 and a heatexchanger E2.

The LNG 1 is first of all expanded and cooled in an expansion turbine X3the speed of which is controlled by a flow controller controlling theflow of LNG through the pipe 1, and is then cooled in the heat exchangerE2 to provide a cooled stream 20. The latter passes through a valve 21,the opening of which is controlled by a pressure controller on the pipe20, upstream of said valve 21, to provide an expanded liquefied naturalgas stream 2. The expanded liquefied natural gas stream 2 is then splitinto a relatively more volatile first top fraction 3 and a relativelyless volatile first bottom fraction 4 in the column C1. The first bottomfraction 4 consisting of cooled liquefied natural gas is collected andpumped in a pump P1, passes through a valve 19 the opening of which iscontrolled by a level controller controlling the level of liquid in thebottom of the vessel V1, and then leaves the installation and goes forstorage.

The column C1 comprises a column bottom reboiler 16 which uses liquidcontained on a plate 17. The stream passing through the reboiler 16 isheated in the heat exchanger E2 and then introduced into the bottom ofthe column C1.

The first top fraction 3 follows the same treatment as set out in FIG.2, to obtain a first compressed gas fraction 5, which is a nitrogen-richcompressed fuel gas, and a second compressed fraction 6 which is atapped-off compressed fuel gas fraction. Similarly, the latter fractionis heated in the exchanger E1 to yield a cooled stream 22. This stream22 is also mixed with the expanded liquefied natural gas stream 2.

Referring now to FIG. 4, the installation depicted is intended, with theaid of a device according to the method of the invention, to treat anitrogen-rich liquefied natural gas 1 to obtain, on the one hand, anitrogen-depleted and cooled liquefied natural gas 4 and, on the otherhand, a nitrogen-rich compressed fuel gas 5.

This installation comprises elements in common with FIG. 3, particularlythe expansion and cooling of the LNG 1 to obtain the expanded LNG stream2. Likewise, the splitting into the first top fraction 3 and the firstbottom fraction 4 is performed in a similar way in the column C1.Finally, the fuel gas stream 5 is obtained, as before, by successivecompression and cooling operations. Unlike the method set out in FIG. 3,a second compressed fraction 6, tapped off the first compressed gasfraction 5 is fed to a compressor XK1 coupled to an expansion turbine X1to obtain a third compressed fraction 7. This fraction is cooled in awater cooler 24, then split into a fourth compressed fraction 8 and afifth compressed fraction 9.

The fourth compressed fraction 8 is cooled in the heat exchanger E1 toprovide a fraction 25 which is expanded in the turbine X1. The turbineX1 supplies an expanded stream 10 which is heated in the exchanger E1 togive a heated expanded stream 26. This heated expanded stream 26 isintroduced into a medium-pressure stage 11 of the compressor K1.

The fifth compressed fraction 9 is cooled in the heat exchanger E1 toprovide a fraction 22 which is expanded in a valve 23 then mixed withthe expanded LNG fraction 2.

The expander X1 comprises an inlet guide valve 27 making it possible, byvarying the angle at which the stream 25 is introduced to the blades ofthe turbine X1, to vary the speed at which the latter rotates, andtherefore to cause the power delivered to the compressor XK1 to vary.

Referring now to FIG. 5, the installation depicted is intended, with theaid of a device according to the method of the invention, to treat aliquefied natural gas 1, preferably nitrogen rich, to obtain, on the onehand, a cooled and nitrogen-depleted liquefied natural gas 4 and, on theother hand, a nitrogen-rich compressed fuel gas 5, when the liquefiednatural gas 1 contains nitrogen.

This installation comprises elements in common with FIG. 4, particularlythe production, by a distillation column C1, of a first top fraction 3and of a first bottom fraction 4. Similarly, the first top fraction 3 iscompressed in a compressor K1 and cooled in coolers 31-34 to obtain afirst compressed fraction 5. A second tapped-off fraction 6 is tappedoff the first compressed fraction 5 to be compressed in a compressor XK1coupled to an expansion turbine X1, which at outlet produces a thirdcompressed fraction 7. The latter is split into a fourth compressedfraction 8 and a fifth compressed fraction 9.

The fourth compressed fraction 8 is cooled in the heat exchanger E1 toprovide a fraction 25 which is expanded in the turbine X1. The turbineX1 supplies an expanded stream 10 which is heated in the exchanger E1 togive a heated expanded stream 26. This heated expanded stream 26 isintroduced into a medium-pressure stage 11 of the compressor K1.

The fifth compressed fraction 9 is cooled in the heat exchanger E1 toprovide a fraction 22 which is expanded in a valve 23, then mixed withthe expanded LNG fraction 2.

The expander X1 comprises an inlet guide valve 27 whose purpose wasdefined in the description of FIG. 4.

Unlike FIG. 4, the installation depicted in FIG. 5 further comprises aseparating vessel V2 in which the expanded natural gas stream 2 is splitinto a second top fraction 12 and a second bottom fraction 13.

The second top fraction 12 is heated in the exchanger E1 then introducedinto a medium-pressure stage 14 of the compressor K1, at a pressure thatit is intermediate between the inlet pressure of the low pressure stage15 and that of the medium-pressure stage 11.

The second bottom fraction 13 is cooled in an exchanger E2 to produce acooled LNG fraction 20. This last fraction is expanded and cooled in avalve 28 to produce an expanded and cooled LNG fraction 29. The openingof the valve 28 is controlled by a level controller controlling thelevel of liquid contained in the vessel V2. The stream 29 is thenintroduced into the column C1 where it is split into the first topfraction 3 and the first bottom fraction 4.

As indicated during the description of FIG. 4, the column C1 comprises areboiler 16 which taps off liquid contained on a plate 17 of the columnC1 to heat it in the exchanger E2 by heat exchange with the stream 13,and introduce it into the bottom of the column. Likewise, the firstbottom fraction 4 is pumped by a pump P1 and passes through a valve 19the opening of which is controlled by a level controller controlling thelevel of liquid present in the bottom of the column C1.

Referring now to FIG. 6, the installation depicted is intended, with theaid of a device according to the method of the invention, to treat aliquefied natural gas 1, preferably nitrogen-depleted, to obtain, on theone hand, a cooled and nitrogen-depleted liquefied natural gas 4 and, onthe other hand, a nitrogen-rich compressed fuel gas 5, when an LNG 1rich in nitrogen is used.

This installation comprises elements common to FIG. 2 and FIGS. 4 and 5.

In a simplified way, FIG. 6 is structurally similar to FIG. 4 exceptthat the column C1 has been replaced by a separating vessel V1, and theexchanger E2 has been omitted, because there is no reboiler when using aseparating vessel. The expanded LNG stream 2 is therefore introduceddirectly into the separating vessel V1 to be split into a first topfraction 3 and a first bottom fraction 4.

Replacing the column C1 with the vessel V1 does not alter the sequenceof steps of the method as described for FIG. 5. By contrast, because thevessel V1 does not have such good separation performance as the columnC1, the cooled LNG 4 will normally contain more nitrogen when a deviceaccording to FIG. 6 is used than when a device according to FIG. 5 isused. Of course, the LNG 1 used in both instances is physically andchemically identical, and contains at least a little nitrogen.

Referring to FIG. 7, the installation depicted is intended, with the aidof a device according to the method of the invention, to treat aliquefied natural gas 1, preferably nitrogen-depleted, to obtain, on theone hand, a cooled liquefied natural gas 4 and, on the other hand, acompressed fuel gas 5.

This installation comprises elements common to FIG. 2 and to FIGS. 4, 5and 6.

In a simplified way, FIG. 7 is structurally similar to FIG. 5 exceptthat the column C1 has been replaced by a separating vessel V1, and theexchanger E2 has been omitted, because there is no reboiler when using aseparating vessel. The expanded LNG stream 2 is therefore introduceddirectly into the separating vessel V2 to be split into a second topfraction 12 and a second bottom fraction 13.

The second top fraction 12 is heated in an exchanger E1 then introducedinto a compressor K1 at an intermediate medium-pressure stage 14,between a low-pressure stage 15 and a medium-pressure stage 11, in thesame way as described for FIG. 5.

Replacing the column C1 with the vessel V1 does not alter the sequenceof steps of the method as described for FIG. 5. By contrast, because thevessel V1 does not have such good separating performance as the columnC1, the cooled LNG 4 will normally contain more nitrogen when a deviceaccording to FIG. 6 is used than when a device according to FIG. 5 isused. Of course, in order to allow for a valid comparison, the LNG 1used in both cases is physically and chemically identical.

In order to allow a material assessment of the performance of aninstallation operating according to a method according to the invention,numerical examples are now given, for illustrative rather thanlimitative purposes.

These examples are given on the basis of two different natural gases “A”and “B”, the composition of which is given below in table 1:

TABLE 1 Natural gas A Natural Gas B Molar Composition Molar Compositioncomposition by mass composition by mass Component (%) (%) (%) (%)Nitrogen 0.100 0.155 3.960 6.127 Methane 91.400 81.378 88.075 78.039Ethane 4.500 7.510 5.360 8.902 Propane 2.500 6.118 1.845 4.493 i-Butane0.600 1.935 0.290 0.931 n-Butane 0.900 2.903 0.470 1.509 Total 100.000100.000 100.000 100.000

These gases are deliberately free of C5 and higher hydrocarbons, so asnot to make the calculations any more complicated.

The other operating conditions are identical and as follows (thereference numerals relate to FIG. 1):

-   -   temperature of the wet natural gas 100: 37° C.    -   pressure of the wet natural gas 100: 54 bar    -   pre-cooling by the cooler 113 prior to drying: 23° C.    -   temperature of the dry gas after it has passed through chamber        116: 23.5° C.    -   pressure of the dry gas: 51 bar    -   temperature of the cooling water: 30° C.    -   temperature at the exit of the water exchanger: 37° C.    -   temperature at which propane condenses: 47° C.    -   efficiency of the centrifugal compressors K1, K2 and K3: 82%    -   efficiency of the expansion turbine X2: 85%    -   efficiency of the axial compressor XK1: 86%    -   power on a GE6 shaft run: 31570 kW    -   power on a GE7 shaft run: 63140 kW    -   power on a GE5 D shaft run: 24000 kW

The power on a shaft run represents the power available on a shaft of ageneral electric gas turbine reference GE5D, GE6 and GE7. Turbines ofthis type are coupled to the compressors K1, K2 and K3 depicted in FIGS.1-7.

The deliveries of natural gas to be liquefied will be chosen to saturatethe available power on the shaft runs. The following three cases areenvisioned (for a liquefication method described in FIG. 1):

-   -   Use for driving one GE6 turbine and one GE7 turbine, which        corresponds to a delivery of LNG produced at −160° C. of about 3        million tonnes per year.    -   Use for driving two GE7 turbines, which corresponds to a        delivery of LNG produced at −160° C. of about 4 million tonnes        per year.    -   Use for driving three GE7 turbines, which corresponds to a        delivery of LNG produced at −160° C. of about 6 million tonnes        per year.

One of the ways for easily calculating the influence of a parameterwithout going into the details of a method is that of the idea ofTheoretical Work associated with the idea of Exergy.

The theoretical work that has to be given to a system in order to causeit to change from state 1 to state 2 is given by the following equation:W 1-2=T 0×(S 1−S 2)−(H 1−H 2)With:

-   W1-2: theoretical work (kJ/kg)-   T0: temperature at which heat is rejected (K)-   S1: entropy in state 1 (kJ/(K.kg))-   S2: entropy in state 2 (kJ/(K.kg))-   H1: enthalpy in state 1 (kJ/kg)-   H2: enthalpy in state 2 (kJ/kg)

In this instance, the rejection temperature will be taken as being equalto 310.15 K (37° C.). State 1 will be the natural gas at 37° C. and 51bar and state 2 will be the LNG at a temperature T2 and at 50 bar.

Table 2 below shows the change in theoretical work to liquefy naturalgases A and B according to the temperature of the LNG leaving theliquefication method. When the power of the refrigeration compressors isconstant, the reduction in theoretical work results in a possibleincrease in the capacity of the liquefication cycle.

TABLE 2 Natural Gas A Temperature Theoretical Theoretical Possible ofthe LNG 1 work work capacity (° C.) (kJ/kg) (%) (%) −130 356.63 71.19140.46 −135 376.93 75.25 132.90 −140 398.45 79.54 125.72 −145 421.5784.16 118.82 −150 446.24 89.08 112.26 −155 472.64 94.35 105.99 −160500.93 100.00  100.00 ************ Natural Gas B −130 355.89 71.35140.16 −135 376.04 75.39 132.65 −140 397.43 79.67 125.51 −145 420.2384.24 118.70 −150 444.56 89.12 112.21 −155 470.74 94.37 105.97 −160498.82 100.00  100.00

It can be seen that the figures obtained with the gases A and B are verysimilar. The possible increase in capacity is about 1.14% per 0° C. oftemperature of the LNG 1 obtained at the exit of the liquefication unitset out in FIG. 1.

The capacity C1 for a temperature T1 of the LNG produced can beexpressed as a function of the capacity C0 at the temperature T0, usingthe following equation:

 C 1=C 0×1.0114^((T1−T0))

With:

-   C1: capacity to produce LNG at T1 (kg/h)-   C0: capacity to produce reference LNG at T0 (kg/h)-   T1: LNG production temperature (° C.)-   T2: reference LNG production temperature (° C.)

As a result, at −140° C., the capacity of the LNG production unit is125.5% of its capacity at −160° C., which is a considerable difference.

The actual work of an LNG production unit will obviously be dependentupon the method chosen. The method depicted in FIG. 1, which is known bythe name of MCR®, is a well known method widely used and developed bythe company APCI.

This method is used here in a special way that gives it very goodperformance: the propane cycle has 4 stages and the MCR (multiplecomponent refrigerant, stream 106, FIG. 1) refrigeration and propanerefrigeration (stream 102, FIG. 1) takes place in the heat exchanger E3,which is a brazed aluminum plate-type exchanger.

The results obtained are set out table 3:

TABLE 3 Natural Gas A Temperature Possible of the LNG 1 Actual workActual work capacity (° C.) (kJ/kg) (%) (%) −130 702.77 72.23 138.45−135 739.93 76.05 131.50 −140 781.25 80.29 124.54 −145 820.56 84.33118.58 −150 867.88 89.20 112.11 −155 917.44 94.29 106.05 −160 972.99100.00  100.00 ************ Natural Gas B −130 688.86 71.24 140.37 −135728.22 75.31 132.78 −140 772.16 79.86 125.23 −145 814.34 84.22 118.74−150 861.75 89.12 112.21 −155 94.37 105.97 −160 100.00  100.00

It can be seen that these results perfectly corroborate those obtainedusing the theoretical work calculations and set out in table 1.

The efficiency of the liquefication method can be calculated from theactual work and from the theoretical work. The latter is roughlyconstant and is round about 51.5%, as can be seen from the results givenin table 4:

TABLE 4 Natural Gas A Temperature Theoretical of the LNG 1 work Actualwork Efficiency (° C.) (kJ/kg) (%) (%) −130 356.63 702.77 50.75 −135376.93 739.93 50.94 −140 398.45 781.25 51.00 −145 421.57 820.56 51.38−150 446.24 867.88 51.42 −155 472.64 917.44 51.52 −160 500.93 972.9951.48 ************ Natural Gas B −130 355.89 688.86 51.66 −135 376.04728.22 51.64 −140 397.43 772.16 51.47 −145 420.23 814.34 51.60 −150444.56 861.75 51.59

This result is particularly satisfying. The user of the method willalways be assured of making best use of the liquefication method,regardless of the chosen temperature at which the LNG is produced. Itcan also be seen that the composition of the natural gas that is to beliquefied has no importance.

Thus, the novel use of the known liquefication method makes it possibleto increase the temperature of the LNG 1 obtained at the outlet of theproduction unit while at the same time allowing a substantial increasein the quantity produced, which may range as high as about 40% at −130°C.

The LNG 1 obtained at the outlet of the production unit described abovefor FIG. 1, can have its nitrogen removed in a denitrogenation unit suchas depicted in FIG. 2 or in FIG. 3. This nitrogen-removal operation isneeded when the natural gas extracted from the source contains nitrogenin relatively high proportions, for example upwards of 0.100 mol % toabout 5 to 10 mol %.

The installation depicted schematically in FIG. 2 is a final flash-typeLNG denitrogenation unit. The flash is obtained at the time the expandedLNG 2 is split into a nitrogen-rich relatively more volatile first topfraction 3 and a nitrogen-depleted relatively less volatile first bottomfraction 4. This separation occurs in a vessel V1, as described above.

According to one mode of operation, the LNG 1 of composition “B” whichcontains nitrogen, produced at −150° C. and at 48 bar is expanded in thehydraulic turbine X3 to a pressure of about 4 bar then in a valve 18 toa pressure of 1.15 bar. The biphasic mixture 2 obtained is split in theseparating vessel V1 into, on the one hand, the nitrogen-rich flash gas3 and, on the other hand, the cooled LNG 4. The cooled LNG is sent forstorage, as described above. The flash gas 3, which constitutes thefirst gaseous fraction, is heated in the exchanger E1 to −70° C. beforebeing compressed to 29 bar in the compressor K1. The compressor K1produces a first compressed fraction 5 which constitutes thenitrogen-rich fuel gas.

About 23% of the first compressed fraction 5 is recycled in the form ofa fraction 6. The latter is cooled in the exchanger E1 by exchange ofheat with the flash gas 3, and is then mixed with the expanded andcooled LNG stream 2.

This arrangement makes it possible to liquefy some of the flash gas(about 23% of it) and to reduce the amount of fuel gas produced. Theperformance of a denitrogenation unit according to this diagram 2 isgiven in table 5 below, in which the column entitled “1 GE6+1 GE7”corresponds to an LNG production unit 1 according to diagram 1,employing 1 GE6 gas turbine and 1 GE7 gas turbine for the compressors K2and K3, “2 GE7” corresponds to the use of 2 GE7 turbines to produce LNG1, and “3 GE7” corresponds to the use of 3 turbines:

TABLE 5 1 GE7 + Units 1 GE6 2 GE7 3 GE7 LNG 1 Temperature ° C. −150 −150−150 Flow rate kg/h 406665 542219 813330 Cooled LNG 4 Flow rate kg/h368990 491985 737980 Specific lower heat kJ/kg 48412 48412 48412 valueNitrogen content mol % 1.38 1.38 1.38 Production of LNG GJ/h % 1786423818 35727 4, lower heat value 100 100 100 Fuel gas 5 Flow rate kg/h37676 50235 75352 Specific lower heat kJ/kg 27492 27492 27492 valueProduction of fuel GJ/h 1036 1381 2072 gas 5, specific lower heat valueDenitrogenation unit Power of kW 7037 9383 14074 compressor K1Performance Specific power of kJ/kg 1019 1019 1019 production of LNGRatio of power of 0.0210 0.0210 0.0210 K1/production of LNG 4

The installation depicted schematically in FIG. 3 is an LNGdenitrogenation unit with a denitrogenation column. Replacing the flashin the vessel V1 with a denitrogenation column C1 allows an appreciableimprovement in the efficiency with which the nitrogen contained in theLNG 1 is extracted.

In this installation, the LNG 1 at −145.5° C. is expanded to 5 bar inthe expansion hydraulic turbine X3, then is cooled from −146.2° C. to−157° C. in the exchanger E2 by exchange of heat with the liquid flowingthrough the column bottom reboiler 16 to obtain an expanded and cooledLNG stream 20. The stream 20 undergoes a second expansion to 1.15 bar ina valve 21 and feeds into the denitrogenation column C1 as a mixturewith the LNG 22 from the partial recycling of the compressed fuel gas 5.

At the bottom of the denitrogenation column C1, the LNG contains 0.06%nitrogen, whereas the nitrogen content of the LNG using a final flashwas 1.38% (FIG. 2 and table 5). This column bottom LNG is pumped by apump P1 and represents a cooled LNG fraction 4 which is sent forstorage.

The fuel gas 3, which is the first top fraction from the column C1, isheated to −75° C. in the exchanger E1, then compressed to 29 bar in thecompressor K1 and cooled by the water coolers 31-34 to provide acompressed fuel gas 5.

A stream 6, which represents 23% of the compressed gas 5 is recycled tothe column C1 after the heating of the stream 3 in the exchanger E1.

The fuel gas produced, which represents 1032 GJ/h in the case of the useof one GE6 turbine and one GE7 turbine, is roughly identical in terms oftotal calorific value to that of the final flash unit of FIG. 2. Thesame is true when using more substantial LNG production units (2 or 3GE7s).

The use of the technique of removing nitrogen in a denitrogenationcolumn has made it possible to increase by 5.62% the capacity of theliquefication process, for a minor on-cost.

It must be understood that it is the combination of use of adenitrogenation column C1 and of the recycling of fuel gas which leadsto this highly encouraging result.

The power of the fuel gas compressor K1 depends on the size of the unit.It will be:

-   -   8087 kW for an LNG unit using 1 GE6 combined with 1 GE7,    -   10783 kW for an LNG unit using 2 GE7s,    -   16174 kW an LNG unit using 3 GE7s.

The powers of these machines and the start-up problems mean that it isdesirable to use a gas turbine to drive the fuel gas compressor K1. Theother performance data for the method are given in table 6:

TABLE 6 1 GE7 + Units 1 GE6 2 GE7 3 GE7 LNG 1 Temperature ° C. −145.5−145.5 −145.5 Flow rate kg/h 428175 570899 856350 Cooled LNG 4 Flow ratekg/h 381659 508877 763318 Specific lower heat kJ/kg 49434 49434 49434value Nitrogen content mol % 0.06 0.06 0.06 Production of LNG GJ/h %18867 25156 37734 4, lower heat value 105.62 105.62 105.62 Fuel gas 5Flow rate kg/h 46517 62023 93034 Specific lower heat kJ/kg 22191 2219122191 value Production of fuel GJ/h 1032 1376 2065 gas 5, specific lowerheat value Denitrogenation unit Power of kW 8087 10783 16174 compressorK1 Performance Specific power of kJ/kg 995 995 995 production of LNGRatio of power of 0.0201 0.0201 0.0201 K1/production of LNG 4 Additionalkg/h 12669 16892 25338 production of GJ/h 1003 1338 2007 LNG

One of the main problems encountered in industrial installations fortreating and liquefying gases is related in particular to the optimumuse of the compression apparatus which represents a significantinvestment, both in terms of initial purchase and in terms of powerconsumption. Indeed, compressors requiring power of the order of severaltens of thousand kW need to be reliable and to be able to be used underconditions of optimum efficiency over the broadest possible range ofloads. Of course, this comment also applies to the means used to runthem, these means here usually being gas turbines, because of thecommercially available range of powers.

Gas turbines in order to be efficient, need to be used at full capacity.Consider the example of a denitrogenation unit operating according toany one of the embodiments described in FIGS. 2 and 3. The gas turbinedriving the compressor K1 needs to have a maximum power tailored to thepower required by the compressor, so as to obtain the most favorablepossible compression efficiency.

However, a gas turbine may find itself operating under conditions suchthat the power delivered to the compressor is markedly below itscapacity.

This is the case for example when a GE5d gas turbine, with a power of24000 kw, is coupled to the compressor K1 when nitrogen is being removedby final flash or by separation in a column. The consequence of thisunderuse of the turbine is a reduction in the energy efficiency of thecompression stage relative to the power consumption of the turbine.

Of course, the power of the compressor K1 varies according to the sizeof the unit, as was explained above. Thus, the use of a GE5d turbinemakes it possible to enjoy excess power amounting to:

-   -   15913 kW for an LNG unit using 1 GE6 turbine associated with 1        GE7 turbine,    -   13217 kW for an LNG unit using 2 GE7 turbines,    -   7826 kW for an LNG unit using 3 GE7 turbines.

It is therefore desirable to use this excess available power. The methodaccording to the invention in particular proposes to use all of theavailable power to drive the compressor K1.

The method according to the invention also makes it possible to increasethe temperature at the outlet of the liquefication method, to obtain theLNG stream 1, and to use the excess power available on the gas turbinedriving K1 to cool the LNG to −160° C.

Furthermore, the method according to the invention makes it possible,because of the possibility of increasing the temperature of the LNG 1produced for example according to the APCI method, to increase the flowrate of LNG cooled to −160° C. substantially, to an extent which in somecases may be by about 40%.

The method of the invention has the merit that it can be implementedeasily, because of the simplicity of the means needed to embody it.

One embodiment according to the method of the invention, employing adenitrogenation column C1, is set out in FIG. 4, described above. Forthe same turbine power driving the compressor K1, the operatingconditions will depend on the capacity of the natural gas liqueficationunit.

An LNG 1 is produced at −140.5° C. using the APCI method depicted inFIG. 1. This method is implemented using two GE7 gas turbines to drivethe compressors K2 and K3. The LNG 1 enters the installation set out inFIG. 4. It is expanded to 6.1 bar in the expansion hydraulic turbine X3driving an electric generator, then cooled from −141.2 to −157° C. in aheat exchanger E2 by exchange of heat with a liquid passing through acolumn bottom reboiler 16 to provide a cooled LNG 21. The latter isexpanded to 1.15 bar in a valve 21 to obtain an expanded stream 2 whichis fed into a column C1 as a mixture with a stream 22, as indicatedabove in the description of the figures.

The LNG stream 4, tapped off at the bottom of the column C1, contains0.00% nitrogen.

The fuel gas 3 is heated to −34° C. in the exchanger E1, then iscompressed to 29 bar in the compressor K1 to feed into a fuel gasnetwork.

A first difference compared with the known method stems from the amountof compressed gas 6 tapped off the fuel gas stream 5: this is now up toabout 73%. This compressed gas 6 is compressed to 38.2 bar in thecompressor XK1 to provide a fraction 7. The latter is cooled to 37° C.in a water exchanger 24 then split into two flows 8 and 9.

The flow 8, which is the larger flow, representing 70% of the stream 7,is cooled to −82° C. by passing through the exchanger E1, then is fed tothe turbine X1, coupled to the compressor XK1. The expanded streamleaving the turbine 10, at a pressure of 9 bar and a temperature of−138° C., is heated in the exchanger E1 to 32° C. then fed into thecompressor K1 at a medium-pressure stage 11 which is the third stage.

The flow 9, which is the smaller flow, representing 30% of the stream 7,is liquefied and cooled to −160° C. and returns to the denitrogenationcolumn C1.

The fuel gas produced represents 1400 GJ/h, and is identical in totalcalorific value to that of the final flash unit. The use of thedenitrogenation technique and of the method of the invention has made itpossible to increase by 11.74% the capacity of the liqueficationsequence, for a reasonable on-cost.

It must be understood that it is the combination of the use of adenitrogenation column, of the recycling of the compressed fuel gas andof the expansion turbine cycle which leads to this highly surprisingresult.

For the other sizes of LNG production unit, the results are given intable 7:

TABLE 7 1 GE7 + Units 1 GE6 2 GE7 3 GE7 LNG 1 Temperature ° C. −138.5−140.5 −143.5 Flow rate kg/h 462359 602827 875470 Cooled LNG 4 Flow ratekg/h 413619 537874 781438 Specific lower heat kJ/kg 49479 49479 49479value Nitrogen content mol % 0.00 0.00 0.00 Production of LNG GJ/h %20465 26613 38661 4, lower heat value 114.57 111.74 108.21 Fuel gas 5Flow rate kg/h 48713 64994 94055 Specific lower heat kJ/kg 21008 2153521521 value Production of fuel GJ/h 1023 1400 2024 gas 5, specific lowerheat value Denitrogenation unit Power of kW 23963 23970 23990 compressorK1 Power of expander kW 2835 2058 1175 X1 Performance Specific power ofkJ/kg 1056 1030 983 production of LNG Ratio of power of 0.0213 0.02080.0199 K1/production of LNG 4 Additional kg/h 44629 45889 43458production of GJ/h 2602 2795 2934 LNG

It can be seen that the increases in capacity are by:

-   -   14.2% for an LNG unit using one GE7 turbine associated with one        GE6 turbine,    -   11.7% for an LNG unit using two GE7 turbines,    -   8.21% for an LNG unit using three GE7 turbines.

The method according to the invention also has a considerable benefit inregulating the amount of fuel gas produced. Indeed, it is now possibleto have sustained production of fuel gas, as shown in a numericalexample in table 8 below:

TABLE 8 Units 2 GE7 LNG 1 Temperature ° C. −135 Flow rate kg/h 641176Cooled LNG 4 Flow rate kg/h 546088 Specific lower heat value kJ/kg 49454Nitrogen content mol % 0.00 Production of LNG 4, lower heat GJ/h % 27006value 113.39 Fuel gas 5 Flow rate kg/h 95092 Specific lower heat valuekJ/kg 29361 Production of fuel gas 5, specific GJ/h 2792 lower heatvalue Denitrogenation unit Power of compressor K1 kW 23900 Power ofexpander X1 kW 802 Performance Specific power of production of LNG 4kJ/kg 1014 Ratio of power of K1/production of 0.0205 LNG 4 Additionalproduction of LNG kg/h 54103 GJ/h 3188

It can be seen that when the amount of fuel gas rises from 1400 to 2800GJ/h, it is then possible to increase the capacity by 13.39%, that is tosay that 1.65% increase in capacity (13.39% minus 11.74%) are due to theincrease in production of fuel gas.

Another embodiment according to the method of the invention, employing adenitrogenation column C1, is set out in FIG. 5 described above. Unlikein FIG. 4, this embodiment employs a separating vessel V2.

The LNG 1, of composition “B” obtained at −140.5° C. under a pressure of48.0 bar with a flow rate of 33294 kmol/h, is expanded to 6.1 bar andminus 141.25° C. in the hydraulic turbine X3, then expanded again to 5.1bar and −143.39° C. in the valve 18, to provide the expanded stream 2.

The stream 2 (33294 kmol/h) is mixed with the stream 35 (2600 kmol/h) toobtain the stream 36 (35894 kmol/h) at −146.55° C.

The stream 35 is made up of 42.97% nitrogen, 57.02% methane and 0.01%ethane.

The stream 36, which is made up of 6.79% nitrogen, 85.83% methane, 4.97%ethane, 1.71% propane, 0.27% isobutane and 0.44% n-butane, is separatedin the vessel 2 into the second top fraction 12 (1609 kmol/h) and thesecond bottom fraction 13 (34285 kmol/h).

The stream 12 (45.58% nitrogen, 54.4% methane and 0.02% ethane) isheated to 33° C. in the exchanger E1 to provide a stream 37 fed, at 4.9bar, to the compressor K1 to the medium-pressure stage 14.

The stream 13 (4.97% nitrogen, 87.30% methane, 5.20% ethane, 1.79%propane, 0.28% isobutane and 0.46% n-butane) is cooled in the heatexchanger E2 to provide the stream 20 at −157° C. and 4.6 bar. Thisstream is expanded in the valve 28 to obtain the stream 29 at −165.21°C. and 1.15 bar, which is introduced into the column C1.

The column C1 produces, at the top, the first top fraction 3 (4032kmol/h) at −165.13° C. The fraction 3 (41.73% nitrogen and 58.27%methane) is heated in the exchanger E1 to give the stream 41 at −63.7°C. and 1.05 bar. The stream 41 is fed into the low-pressure suction side15 of the compressor K1.

The column C1 produces the first bottom fraction 4 at −159.01° C. and1.15 bar with a flow rate of 30253 kmol/h. This fraction 4 (0.07%nitrogen, 91.17% methane, 5.90% ethane, 2.03% propane, 0.32% isobutaneand 0.52% n-butane) is pumped by the pump P1 to provide a fraction 39 at4.15 bar and −158.86° C., then leaves the installation.

The column C1 is equipped with the column bottom reboiler 16 which coolsthe stream 13 to obtain the stream 20.

The compressor K1 produces the compressed flow 5 at 37° C. and 29 barwith a flow rate of 11341 kmol/h. This stream of fuel gas 5 (42.90%nitrogen and 57.09 methane) is split into a stream 40, which represents3041 kmol/h, which leaves the installation, and a stream 6, whichrepresents 8300 kmol/h, which is compressed in the compressor XK1.

The compressor XK1 products the compressed stream 7 at 68.18° C. and39.7 bar. The stream 7 is cooled to 37° C. in the water exchanger 24,then split into the streams 8 and 9.

The stream 8 (5700 kmol/h) is cooled in the exchanger E1 to yield thestream 25 at −74° C. and 38.9 bar.

The stream 9 (2600 kmol/h) is cooled in the exchanger E1 to yield thestream 22 at −155° C. and 38.4 bar. The latter is then expanded in thevalve 23 to provide the stream 35 at −168° C. and 5.1 bar.

The stream 25 is expanded in the expansion turbine X1 which produces thefraction 10 at a temperature of −139.7° C. and a pressure of 8.0 bar.This fraction 10 is then heated in the exchanger E1 which produces thefraction 26 at a temperature of 32° C. and a pressure of 7.8 bar.

The fraction 26 is fed to the compressor K1 on the medium-pressure stage11. The compressor K1 and the expander X1 have the followingperformance:

Denitrogenation unit Power of compressor K1 22007 kW Power of expanderX1  2700 kW

The use of the vessel V2 allows a saving of about 2000 kW on the powerof the compressor K1.

From these studies on the nitrogen-rich gas B, it is evident from themethod according to the invention that:

-   -   the increase in temperature of the LNG leaving the liquefication        method makes it possible to obtain an increase in LNG production        capacity of 1.2% per ° C.,    -   the use of a denitrogenation column associated with        liquefication of some of the fuel gas produced is far more        effective than a final flash,    -   saturation of the power of the gas turbine coupled to the        compressor K1 by use of the novel method makes it possible to        achieve a significant gain in LNG production capacity,    -   the increase in the amount of fuel gas produced makes it        possible to obtain an additional increase in the LNG production        capacity,    -   the addition of the separating vessel V2 makes it possible to        improve the load on the compressor K1 and to lower the cost of        its use.

The following study relates to the use of the nitrogen-depleted gas A,in which the final flash unit produces no fuel gas.

In a known way, natural gas containing very little nitrogen does notrequire the use of a final flash.

The LNG can then be produced directly at −160° C. and be sent forstorage after expansion in a hydraulic turbine, for example similar toX3: this is the highly supercooled approach.

When the highly supercooled technique is chosen the sources of fuel gasmay be various:

-   -   gas from the top of the methane remover,    -   gas from the top of the condensate stabilization column,    -   gas from the evaporation in the storage tanks,    -   gas from regeneration of the natural gas dryers, etc.

It is then no longer possible to add a source of fuel gas withoutrunning the risk of having excess fuel gas. If there is a desire toincrease the capacity of the LNG production line by increasing thetemperature of the LNG produced using the liquefication method, it isnecessary to set up a method that produces little or no fuel gas.

The method according to the invention makes it possible to achieve thisobjective. It makes it possible to increase the temperature of the LNGleaving the liquefication method and therefore to increase the flow rateof cooled LNG 4, produced for storage purposes.

This method is set out in FIG. 6, and was described above. For the samepower of turbine coupled to the compressor K1, the operatingconditions-will depend on the capacity of the liquefication unit. Thecase of the use of LNG 1 from an LNG production unit comprising 2 GE7turbines is described hereinafter by way of example:

The LNG 1 at a temperature of −147° C. is expanded to 2.7 bar in thehydraulic turbine X3 driving an electric generator, then undergoes asecond expansion to 1.15 bar in the valve 18, and is fed to the flashvessel V1, in a mixture with LNG from the liquefication of thecompressed fuel gas 5.

At the bottom of the vessel V1, the LNG is at −159.2° C. and 1.15 bar.It then leaves the installation and goes for storage.

The fuel gas 3, which is the first top fraction, is heated to 32° C. inthe exchanger E1 before being compressed to 29 bar in the compressor K1,to possibly feed into the fuel gas network. In this instance, all of thefuel gas is sent to the compressor XK1 to provide the compressed stream7 at 41.5 bar. This stream is then cooled to 37° C. in the waterexchanger 24, and is then split into two flows 8 and 9.

The stream 8, which represents 79% of the stream 7, is cooled to −60° C.before being fed to the turbine X1 coupled to the compressor XK1. Theturbine X1 provides the expanded gas 10, at a pressure of 9 bar and atemperature of −127° C. This stream 10 is heated in the exchanger E1 toobtain a heated stream 26, at 32° C., then fed into the compressor K1 onthe suction side of its third stage.

The stream 9, which represents 21% of the stream 7, is liquefied andcooled to −141° C. in the exchanger E1 and returns to the flash vesselV1.

The use of the novel method has made it possible to increase by 15.82%the capacity of the liquefication sequence, for a reasonable on-cost.

It must be understood that it is the combination of the recycling of thecompressed fuel gas and of the expansion turbine cycle which leads tothis highly surprising result.

For LNG production units of different size, the results are given in:

-   -   table 9, which corresponds to the characteristics of a unit        operating according to the embodiment of the method of the        invention as set out in FIG. 6,    -   table 10, given by way of comparison, which sets out the        characteristics of an LNG refrigeration unit using the highly        supercooled approach.

TABLE 9 1 GE7 + Units 1 GE6 2 GE7 3 GE7 LNG 1 Temperature ° C. −144 −147−151 Flow rate kg/h 430862 556506 799127 Cooled LNG 4 Flow rate kg/h430862 556506 799127 Specific lower heat kJ/kg 49334 49334 49334 valueNitrogen content mol % 0.10 0.10 0.10 Production of LNG GJ/h % 2125627455 39424 4, lower heat value 100 115.82 110.87 Fuel gas 5 Flow ratekg/h 0 0 0 Specific lower heat kJ/kg 0 0 0 value Production of fuel GJ/h0 0 0 gas 5, specific lower heat value Final flash unit Power of kW24000 24000 23543 compressor K1 Power of expander kW 4719 4719 4850 X1Performance Specific power of kJ/kg 1014 995 984 production of LNG 4Ratio of power of 0.0206 0.0202 0.0199 K1/production of LNG 4 Additionalkg/h 70489 76010 78381 production of LNG GJ/h 3477 3749 3866

TABLE 10 1 GE7 + Units 1 GE6 2 GE7 3 GE7 LNG 1 Temperature ° C. −160−160 −160 Flow rate kg/h 360373 480496 720746 Cooled LNG 4 Flow ratekg/h 360373 480496 720746 Specific lower heat kJ/kg 49334 49334 49334value Nitrogen content mol % 0.10 0.10 0.10 Production of LNG GJ/h %17779 23705 35558 4, lower heat value 100.00 100.00 100.00 Fuel gas 5Flow rate kg/h 0 0 0 Specific lower heat kJ/kg 0 0 0 value Production offuel GJ/h 0 0 0 gas 5, specific lower heat value Final flash unit Powerof compress- kW 0 0 0 or K1 Power of expander kW 0 0 0 X1 PerformanceSpecific power of kJ/kg 973 973 973 production of LNG 4 Ratio of powerof 0.0197 0.0197 0.0197 K1/production of LNG 4 Additional kg/h 0 0 0production of LNG GJ/h 0 0 0

The increases in capacity for the use of an installation according tothe method of the invention, by comparison with the highly supercooledapproach, are as follows:

-   -   19.6% for an LNG unit using 1 GE6 turbine associated with one        GE7 turbine,    -   15.8% for an LNG unit using 2 GE7 turbines,    -   10.9% for an LNG unit using 3 GE7 turbines.

The embodiment of the method according to the invention according toFIG. 6 also allows the production of fuel gas, when this is desired.This eventuality is illustrated in a numerical example in table 11below:

TABLE 11 1 GE7 + Units 1 GE6 LNG 1 Temperature ° C. −143 Flow rate kg/h583534 Cooled LNG 4 Flow rate kg/h 567402 Specific lower heat valuekJ/kg 49351 Nitrogen content mol % 0.06 Production of LNG 4, lower heatGJ/h % 28002 value 118.13 Fuel gas 5 Flow rate kg/h 16132 Specific lowerheat value kJ/kg 48659 Production of fuel gas 5, specific GJ/h 785 lowerheat value Final flash unit Power of compressor K1 kW 23888 Power ofexpander X1 kW 3520 Performance Specific power of production of kJ/kg976 LNG 4 Ratio of power of K1/production of 0.0198 LNG 4 Additionalproduction of LNG kg/h 86906 GJ/h 4297

When the production of fuel gas rises from 0 to 785 GH/h, it is thenpossible to increase the capacity by 18.13%, that is to say that 2.31%of the increase in capacity (18.13% minus 15.82%) are due to theproduction of fuel gas. This result is far more pronounced than the oneobtained with a denitrogenation installation.

Another embodiment according to the method of the invention, employing adenitrogenation column C1, is set out in FIG. 7, described above. Unlikein FIG. 6, this embodiment uses a separating vessel V2.

The LNG 1, of composition “A” obtained at −147° C. at a pressure of 48.0bar with a flow rate of 30885 kmol/h, is expanded to 2.7 bar and minus147.63° C. in the hydraulic turbine X3, then is expanded again to 2.5bar and minus 148.33° C. in the valve 18, to provide the expanded stream2.

The stream 2 (30885 kmol/h) is mixed with the stream 35 (3127 kmol/h) toobtain the stream 36 (34012 kmol/h) at −149.00° C.

The stream 35 is made up of 3.17% nitrogen, 96.82% methane and 0.01%ethane.

The stream 36, which is made up of 0.38% nitrogen, 91.90% methane, 4.09%ethane, 2.27% propane, 0.54% isobutane and 0.82% n-butane, is separatedin the vessel V2 into the second top fraction 12 (562 kmol/h) and thesecond bottom fraction 13 (33450 kmol/h).

The stream 12 (5.41% nitrogen, 94.57% methane and 0.02% ethane) isheated to 34° C. in the exchanger E1, to provide a stream 37 which isfed, at 2.4 bar, to the compressor K1 to the medium-pressure stage 14.

The stream 13 (0.03% nitrogen, 91.85% methane, 4.16% ethane, 2.31%propane, 0.55% isobutane and 0.83% n-butane) is expanded in the valve 28to obtain the stream 29 at −159.17° C. and 1.15 bar, which is introducedinto the separating vessel V1.

The vessel V1 produces, at the top, the first top fraction 3 (2564kmol/h) at −159.17° C. The fraction 3 (2.72% nitrogen, 97.27% methaneand 0.01% ethane) is heated in the exchanger E1 to give the stream 41 atminus 32.21° C. and 1.05 bar. The stream 41 is fed into the low-pressuresuction side 15 of the compressor K1.

The vessel V1 produces the first bottom fraction 4 at −159.17° C. and1.15 bar with a flow rate of 30886 kmol/h. This fraction 4 (0.10%nitrogen, 91.40% methane, 4.50% ethane, 2.50% propane, 0.60% isobutaneand 0.90% n-butane) is pumped by the pump P1 to provide a fraction 39 at4.15 bar and −159.02° C., then leaves the installation.

The compressor K1 produces the compressed stream 5 at 37° C. and 29 barwith a flow rate of 13426 kmol/h. This fuel gas stream 5 (3.18%nitrogen, 96.81% methane and 0.01% ethane) is compressed in full in thecompressor XK1, without producing fuel gas 40.

The compressor XK1 produces the compressed stream 7 at 72.51° C. and42.7 bar. The stream 7 is cooled to 37° C. in the water exchanger 24 andis then split into the streams 8 and 9.

The stream 8 (10300 kmol/h) is cooled in the exchanger E1 to give thestream 25 at −56° C. and 41.9 bar.

The stream 9 (3126 kmol/h) is cooled in the exchanger E1 to give thestream 22 at −141° C. and 41.4 bar. The latter stream is then expandedin the valve 23 to provide the stream 35 at −152.37° C. and 2.50 bar.

The stream 25 is expanded in the expansion turbine X1 which produces thefraction 10 at a temperature of −129.65° C. and a pressure of 8.0 bar.This fraction 10 is then heated in the exchanger E1 which produces thefraction 26 at a temperature of 34° C. and a pressure of 7.8 bar.

The fraction 26 is fed into the compressor K1 on the suction side of themedium-pressure stage 11. The compressor K1 and the expander X1 have thefollowing performance:

Denitrogenation unit K1 Power of compressor K1 23034 kW Power ofexpander X1  2700 kW

The use of the vessel V2 allows a saving of about 1000 kW on the powerof the compressor K1.

Finally, from these studies on gas A, which is nitrogen-depleted, it isevident from the method according to the invention that:

-   -   the increase in the temperature of the LNG leaving the        liquefication method makes it possible to obtain an increase in        LNG production capacity of 1.2% per ° C., this result being        identical to the one obtained with gas A,    -   the use of a final flash (vessel V1) and the saturation of the        power of the gas turbine driving the compressor K1 makes it        possible, by virtue of the method of the invention, to obtain a        significant gain in LNG production capacity, without producing        fuel gas,    -   the production of fuel gas makes it possible to obtain an        increase in the LNG production capacity. This gain is not        insignificant and may prove to be a decisive factor,    -   the addition of the separating vessel V2 makes it possible to        improve the load on the compressor K1 and to reduce the cost of        using it.

1. A method for refrigerating a pressurized liquefied natural gas,wherein the gas contains methane, C₂ and higher hydrocarbons, the methodcomprising: (Ia) expanding the pressurized liquefied natural gas toprovide an expanded liquefied natural gas stream; (Ib) splitting theexpanded liquefied natural gas stream into a relatively more volatilefirst top fraction and a relatively less volatile first bottom fractioncomprised of refrigerated liquefied natural gas; (Ic) collecting thefirst bottom fraction comprised of refrigerated liquefied natural gas;(Id) heating the first top fraction, compressing the heated first topfraction by a first compression step and then cooling the compressed topfraction for providing a first fuel gas compressed fraction, andcollecting the first fuel gas compressed fraction; (Ie) tapping off asecond compressed fraction from the first compressed fraction, coolingthe second compressed fraction and then mixing the cooled secondcompressed fraction with the expanded liquefied natural gas stream;(IIa) compressing the second compressed fraction in a second compressionstep which is coupled to an expansion turbine for providing a thirdcompressed fraction; (IIb) cooling the third compressed fraction;splitting the third compressed fraction into a fourth compressedfraction and a fifth compressed fraction; (IIc) cooling the fourthcompressed fraction and expanding the fourth compressed fraction in theexpansion turbine coupled to the second compression step for providingan expanded fraction, and heating the expanded fraction; introducing theexpanded fraction into a medium-pressure first stage of the firstcompression; and (IId) cooling the fifth compressed fraction and thenmixing the cooled fifth compressed fraction with the expanded liquefiednatural gas stream.
 2. The method of claim 1, wherein prior to step(Ib), splitting the expanded liquefied natural gas stream into a secondtop fraction and a second bottom fraction; heating the second topfraction, then introducing the heated second top fraction into the firstcompression step in an intermediate medium-pressure second stage betweenthe medium-pressure first stage and a low-pressure stage; splitting thesecond bottom fraction into the first top fraction and the first bottomfraction.
 3. The method of claim 1, further comprising cooling each gasfraction after each of the respective compression steps.
 4. Arefrigerated liquefied natural gas obtained by performing the method ofclaim
 1. 5. Apparatus for refrigerating a pressurized liquefied naturalgas, wherein the gas contains methane, C₂ and higher hydrocarbons, theapparatus comprising: (Ia) first means for expanding the pressurizedliquefied natural gas for providing an expanded liquefied natural gasstream; (Ib) second means for splitting the expanded liquefied naturalgas into a relatively more volatile first top fraction and a relativelyless volatile first bottom fraction; (Ic) a first collector forcollecting the first bottom fraction comprised of refrigerated liquefiednatural gas; (Id) a heater for heating the first top fraction, a firstcompressor for compressing the heated top fraction and first coolingmeans for cooling the compressed top fraction for providing a fuel gascompressed fraction, and a second collector for collecting the fuel gascompressed fraction; (Ie) a tap for tapping off the fuel gas compressedfraction from the second collector for providing a second compressedfraction; second cooling means for cooling the second compressedfraction and a mixer for mixing the second compressed fraction with theexpanded liquefied natural gas stream; (IIa) a second compressor forreceiving the second compressed fraction and for compressing the secondcompressed fraction, an expansion turbine coupled to the secondcompressor for providing a third compressed fraction from thecompressor; (IIb) a first cooler for cooling the third compressedfraction; means for splitting the third compressed fraction into afourth compressed fraction and a fifth compressed fraction; (IIc) asecond cooler for cooling the fourth compressed fraction andcommunicating the fourth compressed fraction to the expansion turbinecoupled to the second compressor for providing an expanded fraction; aheater for heating the expanded fraction; the first compressor having amedium-pressure first stage into which the heated expanded fraction iscommunicated; (IId) a third cooler for cooling the fifth compressedfraction and a mixer for receiving the fifth compressed fraction andmixing the fifth compressed fraction with the expanded liquefied naturalgas stream.
 6. The apparatus of claim 5, further comprising: a means forsplitting the expanded liquefied natural gas stream into a second topfraction and a second bottom fraction prior to (Ib) the second means forsplitting; means for heating and then for introducing the second topfraction into the first compressor in an intermediate medium-pressuresecond stage between the medium-pressure first stage and a low-pressurestage; and means for splitting the second bottom fraction into the firsttop fraction and the first bottom fraction.
 7. The apparatus of claim 6,further comprising a first separating vessel for separating the firsttop fraction and the first bottom fraction.
 8. The apparatus of claim 6,further comprising a distillation column for separating the first topfraction and the first bottom fraction.
 9. The apparatus of claim 7,further comprising a separating vessel for splitting the expandedliquefied natural gas stream into the second top fraction and the secondbottom fraction.
 10. The apparatus of claim 8, wherein the distillationcolumn comprises at least one of a lateral or a column-bottom reboiler;the distillation column having a plate and liquid is tapped off theplate of the distillation column and is connected to pass through thereboiler, a heat exchanger for heating the liquid passing through thereboiler, and a connection for reintroducing the heated liquid into thedistillation column and a stage below the plate thereof; the expandedliquefied natural gas stream is communication with the heat exchanger tobe cooled in the heat exchanger.
 11. The apparatus of claim 10, whereinthe heat exchanger is connected to the first, expanded, fourth and fifthcompressed fractions for causing cooling of the first top fraction andof the expanded fraction and heating of the fourth and the fifthcompressed fractions.
 12. The apparatus of claim 11, wherein the heatexchanger communicates with a second top fraction for heating the secondtop fraction in the heat exchanger.